Consumable downhole packer or plug

ABSTRACT

A packer or plug for use in a wellbore includes: a tubular mandrel made from a composite material including a pyrotechnic composition; an expandable seal disposed on an outer surface of the mandrel; and an igniter operable to initiate combustion of the mandrel.

BACKGROUND OF THE INVENTION

Field of the Invention

The present invention generally relates to a consumable downhole packeror plug.

Description of the Related Art

Hydraulic fracturing (aka fracing or fracking) is an operation forstimulating a subterranean formation to increase production of formationfluid, such as crude oil and/or natural gas. A fracturing fluid, such asa slurry of proppant (i.e., sand), water, and chemical additives, ispumped into the wellbore to initiate and propagate fractures in theformation, thereby providing flow channels to facilitate movement of theformation fluid into the wellbore. The fracturing fluid is injected intothe wellbore under sufficient pressure to penetrate and open thechannels in the formation. The fracturing fluid injection also depositsthe proppant in the open channels to prevent closure of the channelsonce the injection pressure has been relieved. Typically, a wellborewill intersect several hydrocarbon-bearing production zones. Each zonemay have a different fracture pressure. To ensure that each zone istreated, each zone is treated separately while isolating a previouslytreated zone from the next zone to be treated using a frac plug.

SUMMARY OF THE INVENTION

The present invention generally relates to a consumable downhole packeror plug. In one embodiment, a packer or plug for use in a wellboreincludes: a tubular mandrel made from a composite material including apyrotechnic composition; an expandable seal disposed on an outer surfaceof the mandrel; and an igniter operable to initiate combustion of themandrel.

In another embodiment, a method of manufacturing a downhole packer orplug includes: mixing polymer reagents and a pyrotechnic composition,thereby forming a resin; guiding fibers through the resin, therebycoating the fibers; consolidating the coated fibers into a fiber bundle;and rotating a winding mandrel to spool the fiber bundle, therebyforming a component of the packer or plug.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIGS. 1A and 1B illustrate a fracturing system, according to oneembodiment of the present invention.

FIG. 2 illustrates a consumable frac plug of the system.

FIG. 3A illustrates an igniter of the frac plug. FIGS. 3B and 3Cillustrate a trigger of the igniter.

FIGS. 4A and 4B illustrate a manufacturing system for a mandrel of thefrac plug.

FIGS. 5A-5F illustrate a fracturing operation conducted using thesystem.

FIG. 6A illustrates an alternative consumable frac plug, according toanother embodiment of the present invention. FIG. 6B illustrates anigniter of the alternative frac plug.

FIG. 7A illustrates an electronic trigger for use with either igniter,according to another embodiment of the present invention. FIG. 7Billustrates an alternative switch for the electronic trigger, accordingto another embodiment of the present invention.

FIG. 8 illustrates an alternative manufacturing system for analternative consumable mandrel, according to another embodiment of thepresent invention.

DETAILED DESCRIPTION

FIGS. 1A and 1B illustrate a fracturing system 1, according to oneembodiment of the present invention. The fracturing system 1 may includea lubricator 1 b, a fluid system 1 f, a production tree 1 p, a workline, such as wireline 1 w, and a bottomhole assembly (BHA) 1 h.

Alternatively, the work line may be slick line or sand line.Alternatively, a work string, such as coiled tubing, may be used insteadof the work line.

A wellhead 2 may be mounted on an outer casing string 3 o which has beendeployed into a wellbore 4 drilled from a surface 5 s of the earth andcemented 6 o into the wellbore. An inner casing string 3 i has beendeployed into the wellbore 4, hung from the wellhead 2, and cemented 6 iinto place. The outer casing string 3 o may extend to a depth adjacent abottom of an upper formation 5 u and the inner casing string 3 i mayextend through a lower formation 5 b. The upper formation 5 u may benon-productive and the lower formation 5 b may be a hydrocarbon-bearingreservoir having one or more production zones 7 (only one shown).

Alternatively, although shown as vertical, the wellbore 4 may include avertical portion and a deviated, such as horizontal, portion.

The production tree 1 p may be installed on the wellhead 2. Theproduction tree 1 p may include a master valve 8 m, a flow cross 9, anda swab valve 8 s. Each component of the production tree 1 p may beconnected together, the production tree may be connected to the wellhead2 and an injector head 10, and the lubricator 1 b may be connected tothe injector head, such as by flanges and studs or bolts and nuts.

The fluid system 1 f may include the injector head 10, shutoff valve 11,one or more gauges, such as the pressure gauges 12 p,t and a strokecounter 13, a launcher 14, a fracture pump 15, and a fracture fluidmixer, such as a recirculating mixer 16. The pressure gauge 12 t may beconnected to the flow cross 9 and may be operable to monitor wellheadpressure. The pressure gauge 12 p may be connected between the fracturepump 15 and the valve 11 and may be operable to measure dischargepressure of the fracture pump 15. The stroke counter 13 may be operableto measure a flow rate of the fracture pump 15.

Alternatively, the gauges may be sensors in data communication with aprogrammable logic controller (PLC) (not shown) for automated orsemi-automated control of the fracturing operation.

The launcher 14 may include a housing, a plunger, and an actuator. Apump-down plug, such as a ball 17, may be disposed in the plunger forselective release and pumping downhole to close a bore of a consumablefrac plug 18 of the BHA 1 h. The plunger may be movable relative to thehousing between a capture position and a release position. The plungermay be moved between the positions by the actuator. The actuator may behydraulic, such as a piston and cylinder assembly. In operation, atechnician may release the ball 17 by operating the launcher actuator.The launcher actuator may then move the plunger to the release position(not shown). The carrier and ball 17 may then move into a dischargeconduit connecting the fracture pump 15 to the injector head 10. Thepumped stream of fracturing fluid 19 (FIG. 5C) may then carry the ball17 from the launcher 14, into the wellhead 2 via the injector head 10and tree 1 p, and to the frac plug 18.

Alternatively, the actuator may be electric, pneumatic, or manual, suchas a handwheel.

The lubricator 1 b may include a tool housing 20 (aka lubricator riser),a seal head 21, one or more blowout preventers 22, and the shutoff valve8 f. Components of the lubricator 1 b may be connected, such as byflanged connections. The shutoff valve 8 f may also have a lower flangefor connecting to an upper flange of the injector head 10. The seal head21 may include a stuffing box and a grease injector. The stuffing boxmay include a packing, a piston, and a housing. A port may be formedthrough the housing in communication with the piston. The port may beconnected to a hydraulic power unit (not shown) of a service truck (notshown) via a hydraulic conduit (not shown). When operated by hydraulicfluid, the piston may longitudinally compress the packing, therebyradially expanding the packing inward into engagement with the wireline1 w.

The grease injector may include a housing integral with the stuffing boxhousing and one or more seal tubes. Each seal tube may have an innerdiameter slightly larger than an outer diameter of the wireline 1 w,thereby serving as a controlled gap seal. An inlet port and an outletport may be formed through the grease injector/stuffing box housing. Agrease conduit (not shown) may connect an outlet of a grease pump (ofthe service truck) with the inlet port and another grease conduit (notshown) may connect the outlet port with a grease reservoir. Grease (notshown) may be injected from the grease pump into the inlet port andalong the slight clearance formed between the seal tube and the wireline1 w to lubricate the wireline 1 w, reduce pressure load on the stuffingbox packing, and increase service life of the stuffing box packing.

The BHA 1 h may include a cablehead 23, a casing collar locator (CCL)24, a perforation gun 25, a setting tool 26, and the consumable fracplug 18. The cablehead 23, CCL 24, and perforation gun 25 may beconnected together, such as by threaded connections or flanges and studsor bolts and nuts. The perforation gun 25 may include a firing head anda charge carrier. The charge carrier may include a housing, a plurality(ten shown) of shaped charges, and detonation cord connecting thecharges to the firing head. In operation, the firing head may receiveelectricity from the wireline 1 w to operate an electric match thereof.The electric match may ignite the detonation cord to fire the shapecharges.

The setting tool 26 may include a mandrel 26 m (FIG. 2) and a piston 26s longitudinally movable relative to the mandrel. The mandrel 26 m maybe connected to the perforation gun and fastened to a mandrel 27 of thefrac plug 18, such as by shearable pins 35, screws, or ring. The settingtool 26 may include a firing head and a power charge. In operation, thefiring head may receive electricity from the wireline 1 w to operate anelectric match thereof and fire the power charge. Combustion of thepower charge may create high pressure gas which exerts a force on thesetting piston 26 s.

Alternatively, a hydraulic pump may be used instead of the power chargeto drive the setting piston. If coiled tubing is used instead of thewireline, high pressure fluid may be injected through the coiled tubingto drive the setting piston.

FIG. 2 illustrates the consumable frac plug 18. The frac plug 18 mayinclude a consumable mandrel 27, one or more anchors, such as upper 28 uand lower 28 b slips and respective upper 29 u and lower 29 b slipcones, an expandable sealing member, such as packing element 30, and anigniter 31. The frac plug 18 may further include one or more packingsupports, such as upper 32 u and lower 32 b expansion rings andrespective upper 33 u and lower 33 b support cones. The frac plug 18 maybe made from one or more drillable materials. The cones 29 u,b and 33u,b may be made from a composite material. The composite material mayinclude a polymer matrix reinforced by continuous fibers such as glass,carbon, or aramid (including para-aramids and meta-aramids). The polymermatrix may be epoxy, polyurethane or phenolic. The slips 28 u,b may bemade from a non-steel metal or alloy, such as cast iron. The packingelement 30 may be made from a polymer, such as an elastomer or elastomercopolymer. The expansion rings 32 u,b may be made from an engineeringpolymer, such as polytetrafluoroethylene (PTFE) or polyetheretherketone(PEEK).

The plug components 28-34 may be disposed along an outer surface of themandrel 27. The packing element 30 and packing supports 32 u,b, 33 u,bmay be disposed between the slip cones 29 u,b and the upper 32 u, 33 uand lower 32 b, 33 b packing supports may straddle the packing element.A seal, such as an o-ring 34 u,b, may be disposed between each supportcone 33 u,b and the mandrel 27 to seal the interface formedtherebetween. The expansion rings 32 u,b may be disposed along themandrel 27 between the support cones 33 u,b, and the slip cones 29 u,b.

The expansion rings 32 u,b may each be an annular member having a baseportion of a first diameter that steps up to a wedge portion of a seconddiameter. An inner surface of the wedge portion may taper outwardly froma longitudinal axis of the frac plug 18. The expansion rings 32 u,b mayfurther have a shoulder may be formed between the two portions. Eachsupport cone 33 u,b may have a cone portion and a support portion. Thecone portion of each support cone 33 u,b may be complimentary tapered tothe wedged portions of the respective expansion rigs 32 u,b. Equallyspaced longitudinal cuts may be fabricated in the wedge portion tocreate one or more wedges therebetween. The number of cuts may bedetermined by the size of the annulus to be sealed and the forcesexerted on each expansion support ring 32 u,b.

In operation, the angled wedges may pivot radially outward as eachexpansion ring 32 u,b moves along the outer surface of each respectivesupport cone 33 u,b. The wedges may then sever from the base portion,and may extend radially to contact an inner surface of the inner casing3 i (FIG. 5A). The extended wedges may serve as a brake that preventsslippage of the frac plug 18 relative to the inner casing 3 i. Thesupport portion of each support cone 33 u,b may abut the packing element30. A reaction force exerted on each support cone by extension of thewedges may serve to anchor the support cone in place along the mandrel27 to prevent longitudinal slippage of the expanded packing element 30.

The mandrel 27 may be a tubular member having a longitudinal bore formedtherethrough. The mandrel 27 may have a body portion 27 y, guideprofile, such as a mule shoe 27 m, formed at a lower end thereof, ashoulder 27 s formed in an outer surface thereof for receiving the plugcomponents 28-34, and a seat 27 b formed in an inner surface thereof forreceiving the ball 17.

The slips 28 u,b may each be disposed along the mandrel 27 adjacent therespective slip cone 29 u,b. Each slip 28 u,b may include an inner baseportion having a tapered inner surface conforming to the respective slipcone 29 u,b and an outer wedge portion split into a plurality of wedges.An outer surface of each wedge may have at least one outwardly extendingserration to engage an inner surface of a the inner casing 3 i when theslips 28 u,b are driven radially outward from the mandrel 27 due tomovement across the respective slip cones 29 u,b. The slip base portionsmay each be designed to fracture with radial stress. Each slip baseportion may include at least one recessed groove (not shown) milledtherein to fracture under stress allowing the wedges to expand outwardto engage the inner casing 3 i.

Each slip cone 29 u,b may be fastened to the mandrel 27, such as by oneor more respective shearable pins 36 u,b, screws, or ring. Each of theslip cones 29 u,b may have an undercut formed in an end thereof forreceiving the base portion of the respective expansion ring 32 u,b. Asetting ring 37 may be disposed along the mandrel 27 adjacent the upperslip 28 u for receiving the setting piston 26 s. The setting ring 37 maybe captured on the mandrel 27 by a stop 38. The stop 38 may be anannular member and fastened to the mandrel 27, such as by one or morepins 39 a,b, screws, or snap ring.

Alternatively, each support cone may be two separate tapered members andone member made from the engineering polymer such that it may extrude tofill voids between the wedges. Alternatively, the frac plug may furtherinclude a ball cage and the ball trapped in the ball cage.Alternatively, the frac plug may further include a bore plug disposed inthe mandrel bore or a solid mandrel, thereby converting the frac plug toa bridge plug.

FIG. 3A illustrates the igniter 31. FIGS. 3B and 3C illustrate a trigger47 of the igniter 31. The igniter 31 may include an upper portion of themandrel body 27 y, an inner housing 41, a pyrogen charge 45, one or more(two shown) pyrotechnic composition charges (PCCs) 46 c, and the trigger47. The trigger 47 may include a outer housing 40, one or more strikers44, and one or more solute plugs 53. Each striker 44 may include apressure relief device 48, a plunger 50, a solvent 51, and a pressureport 54.

The outer housing 40 and inner housing 41 may each be made from thenon-steel metal or alloy. The inner housing 41 may be connected to themandrel 27, such as by bonding with an adhesive. The inner housing 41may have upper and lower shoulders formed at ends thereof to engage theouter housing 40, thereby defining an annular chamber between the innerand outer housings. The inner housing 41 may also have one or morecharge ports formed through a wall thereof for receiving the respectivePCCs 46 c. The mandrel body 27 y may also have one or more socketsformed in an outer surface thereof for receiving the respective PCCs 46c. Each inner housing shoulder may also have a groove formed therein forreceiving a seal, such as an o-ring 42 u,b. The outer housing 40 may befastened to the inner housing 41, such as by a snap ring 43 or screws orbonded thereto.

The pyrogen charge 45 may be a powder or ribbons made from awater-reactive agent, such as magnesium, and having an ignitiontemperature sufficient to ignite the PCCs 46 c. The PCCs 46 c may eachbe made from a pyrotechnic composition 46 m (FIG. 4A). The pyrotechniccomposition 46 m may include a fuel and an oxidant and may be thermiteor thermate. Each PCC 46 c may be a pellet of the pyrotechniccomposition 46 m.

Alternatively, the pyrogen charge may further include an oxidant or be amixture of the pyrotechnic composition and water-reactive agent.Alternatively, the pyrogen agent may react with other components ofwellbore fluid or chemicals injected into the well. Alternatively, thePCC 46 c may be a tube made of the mandrel material (discussed below)and packed with the water-reactive agent and/or pyrotechnic composition.The alternative tube may also have diffusion holes formed through a wallthereof.

The pressure relief device 48 may include a rupture disk 48 d and a pairof flanges 48 i,o. The pressure port 54 may be formed through a wall ofthe outer housing 40. The pressure port 54 may have a first shoulderformed therein for receiving the flanges 48 i,o and be threaded. One ofthe flanges 48 o may be threaded for fastening the pressure reliefdevice 48 to the outer housing 40. The rupture disk 48 d may be metallicand have one or more scores formed in an inner surface thereof forreliably failing at a predetermined rupture pressure. The rupture disk48 d may be disposed between the flanges 48 i,o and the flangesconnected together, such as by one or more fasteners 48 f. The flanges48 i,o may carry one or more seals 48 s for preventing leakage aroundthe rupture disk 48 d.

The plunger 50 may be disposed in the pressure port 54 and fastened tothe outer housing 40, such as by a shearable ring 49 r. The shearablering 49 r may be received by a second shoulder of the pressure port 54.The plunger 50 may have a cylindrical portion and a conical portion. Thecylindrical portion may have a first groove for receiving the shearablering 49 r and a second groove for receiving a seal, such as an o-ring 49s. The solvent 51 may be contained in a frangible container, such as aglass vial. The glass vial may be fastened to the outer housing 40, suchas by entrapment between a third shoulder of the pressure port 54 and astop, such as snap ring 52. The outer housing 40 may further have one ormore ignition ports formed through as wall thereof. A solute plug 53 maybe disposed in each ignition port and fastened to the housing, such asby a threaded connection.

In operation, the rupture pressure may correspond to a fracture pressureof the production zone 7. The disk 48 d may be operable to rupture atcommencement of the fracturing operation thereby opening the pressureport 54. The fracture pressure may exert a fluid force on the plunger50, thereby fracturing the shearable ring 49 r and propelling theplunger into the glass vial containing the solvent 51. The solvent 51may be expelled into the annular chamber in communication with thesolute plugs 53. The solvent 51 and solute may be a soluble pair, suchas an acid and metal. The solvent 51 may gradually dissolve the soluteplugs 53 until the pressure capability thereof is compromised, therebyleaking fracturing fluid 19 through the ignition ports and into theannular chamber. The solute plugs 53 may be configured to withstandattack by the solvent 51 for a predetermined time period sufficient tocomplete the fracturing of the production zone 7. The pyrogen charge 45may react with water in the fracturing fluid 19, thereby combusting andheating the PCCs 46 c to ignition temperature. The PCCs 46 c may in turnignite the mandrel 27.

FIGS. 4A and 4B illustrate a manufacturing system for the mandrel 27.The manufacturing system may include two or more liquid tanks, ametering pump 55 p for each liquid tank, a metering hopper 55 h, and amixing trough 55 t. An inlet of each metering pump 55 p may be connectedto the respective liquid tank. A first of the liquid tanks may include afirst polymer reagent, such as epoxide 54 m, and a second of the tanksmay include a second polymer reagent, such as polyamine 54 h. Themetering hopper 55 h may include the pyrotechnic composition 46 m inpowder or nanoparticle form.

In operation, the metering pumps 55 p and metering hopper 55 m may beoperated to dispense proportionate quantities of the reagents 54 m,h andthe PCC 46 into the mixing trough 55 t. The mixing trough 55 t may thenmix the quantities into a resin 56. The resin 56 may include an uncuredpolymer, such as epoxy, infused with the pyrotechnic compositionparticulates.

Alternatively, the first reagent may be isocyanate and the secondreagent may be polyol. Alternatively, the first reagent may be phenoland the second reagent may be formaldehyde. Alternatively, themanufacturing system may include a third liquid tank containing adiluent and a third metering pump for dispensing the diluent into themixing trough or one or both of the reagents may be pre-diluted.

Once the resin 56 has been mixed, a blank 27 k of the mandrel 27 may beformed by filament winding. Continuous fibers 57 f, such as glass,carbon, or aramid (including para-aramids and meta-aramids) fibers, maybe fed through the mixed resin 56 via one or more sheaves of the mixingtrough 55 t, thereby coating the fibers with the resin. The coatedfibers 57 c may continue into a fiber placement hood 58 h. The fiberplacement hood 58 h may consolidate the multiple coated fibers 57 c intoa fiber bundle 57 g and feed the fiber bundle to a winding mandrel 59 w,thereby forming the plug mandrel blank 27 k.

The fiber placement hood 58 h and the winding mandrel 59 w may bepositioned parallel to one another. The fiber placement hood 58 h mayinclude a carriage 58 c and a track 58 t. The carriage 58 c may bereciprocated along a longitudinal axis of the track 58 t, such as by alinear actuator (not shown). As the carriage 58 c is translated alongthe track 58 t, the winding mandrel 59 w may be rotated about a windingaxis 59 x, such as by an electric motor (not shown). As the fiber bundle57 g is fed from the fiber placement hood 58 h to the rotating windingmandrel 59 w, the fiber placement hood 58 h may dispense the fiberbundle 57 g to the winding mandrel at a winding angle 58 a relative tothe winding axis 59 x. The winding angle 58 a may range from thirty toseventy degrees. The winding angle 58 a of the fiber placement hood 58 hmay be altered by adjusting the speed that the carriage 58 c translatesalong the track 58 t relative to the angular speed of the windingmandrel 59 w. Each pass of the carriage 58 c along the track 58 t mayform a respective layer of the mandrel blank 27 k and the carriage maybe reciprocated until a desired outer diameter of the blank 27 k isformed.

Once the mandrel blank 27 k has been formed, the mandrel blank andwinding mandrel 59 w may be placed in an oven (not shown) and heatedand/or irradiated to cure the resin 56. After curing, the mandrel blank27 k may be removed from the winding mandrel 59 w and machined to formthe plug mandrel 27.

Alternatively, the fibers 57 f may be pre-impregnated with the resin 56and dry wound or post-impregnated with the resin. Alternatively, themandrel blank 27 k may be formed by pultrusion. Alternatively, themandrel blank 27 may be compression molded, injection molded, orreaction injection molded using mats impregnated with the resin 56 or amixture of the resin 56 and chopped fiber. Alternatively, other plugcomponents, such as the cones 29 u,b, 33 u,b and/or fasteners 35, 36u,b, 39 a,b, may be made using the resin 56 or coated fibers 57 c.Alternatively, a tubular for a downhole tool may be made instead of themandrel blank 27 k.

FIGS. 5A-5F illustrate a fracturing operation conducted using the system1. The BHA 1 h may be deployed into the wellbore 4 using the wireline 1w with assistance from the fracture pump 15. The fracture pump 15 may beoperated to pump displacement fluid (not shown) just before the BHA 1 hhas been inserted into the wellbore 4. Pumping of the displacement fluidmay increase pressure in the inner casing bore until a differential issufficient to open a toe sleeve (not shown) of the inner casing string 3i. Once the toe sleeve has been opened, the BHA 1 h may be inserted intothe wellbore 4 and continued pumping of the displacement fluid may drivethe BHA 1 h to a setting depth below the production zone 7. Thedisplaced fluid may be forced into the lower formation 5 b via the opentoe sleeve.

Once the BHA 1 h has been deployed to the setting depth, the frac plug18 may be set by supplying electricity to the BHA at a first polarityvia the wireline 1 w to activate the setting tool 26. As discussedabove, the setting piston 26 s may be driven toward the mule shoe 27 mwhile the wireline 1 w restrains the setting mandrel 26 m and plugmandrel 27, thereby compressing the packing element 30 and driving theslips 28 u,b along the respective slip cones 29 u,b. The packing element30 may be radially expanded into engagement with the inner casing string3 i and the slips 28 u,b may be radially extended into engagement withthe inner casing.

A tensile force may then be exerted on the BHA 1 h by pulling thewireline 1 w from the surface 5 s to fracture the shearable pins 35,thereby releasing the frac plug 18 from the rest of the BHA 23-26. Theremaining BHA 23-26 may then be raised using the wireline 1 w until theperforation guns 25 are aligned with the production zone 7. Electricitymay then be resupplied to the remaining BHA 23-26 via the wireline 1 wat a second polarity to fire the perforation guns 25 into the innercasing 3 i, thereby forming perforations 60 p. Once the perforations 60p have been formed, the remaining BHA 23-26 may be retrieved to thelubricator 1 b and into the tool housing 20 using the wireline 1 w. Thelubricator shutoff valve 8 f may then be closed.

The ball 17 may then be released from the launcher 14 and the fracturingfluid 19 may be pumped from the mixer 16 into the injector head 10 viathe valve 11 by the fracture pump 15. As discussed above, the fracturingfluid 19 may be a slurry including: proppant (i.e., sand), water, andchemical additives. Continued pumping of the fracturing fluid 19 maydrive the ball 17 toward the frac plug 18 until the ball lands onto theplug mandrel seat 27 b, thereby closing the plug mandrel bore.

Continued pumping of the fracturing fluid 19 may exert pressure on theseated ball 17 until pressure in the inner casing string 3 i increasesto force the fracturing fluid (above the seated ball) through theperforations 60 p, cement 6 i and into the production zone 7 by creatinga fracture 60 f. The increased pressure may also fracture the rupturedisk 48 d and drive the plunger 50 into the solvent vial of the trigger47. As discussed above, the proppant may be deposited into the fracture60 f by the fracturing fluid 19. Pumping of the fracturing fluid 19 maycontinue until a desired quantity has been pumped into the productionzone 7. Once the solute plugs 53 are compromised by the solvent 51, theigniter 31 may initiate incineration 61 of the plug mandrel 27. Once theplug mandrel 27 has been incinerated 61 leaving only plug debris 18 d,one or more additional production zones (not shown) may be fracturedusing one or more additional respective BHAs (not shown) in a similarfashion.

Once the fracturing operation of all the production zones 7 has beencompleted, the lubricator 1 b and injector head 10 may be removed fromthe tree 1 p. The flow cross 9 may be connected to a disposal pit ortank (not shown) and fracturing fluid 19 allowed to flow from thewellbore 4 to the pit. A work string, such as coiled tubing 1 c, and anadditional BHA 62 j,s may be deployed into the wellbore 4 using a coiledtubing unit (CTU) (not shown). The CTU may include an injector, a reelof the coiled tubing 1 c, a tool housing, a stuffing box, one or moreBOPs and a shutoff valve. The BHA 62 j,s may include a jetting tool 62 jand a guide shoe 62 s. The injector may be operated to lower the coiledtubing 62 c and BHA 62 j,s into the wellbore 4 and the fracture pump 15operated to inject washing fluid through the BHA 62 j,s to the jettingtool 62 j. The jetting tool 62 j may spray the washing fluid against theinner casing string 3 i to dislodge the plug debris 18 d and thereturning washing fluid may carry the plug debris to the surface fordisposal. The BHA 62 j,s and coiled tubing 62 c may then be retrieved tothe surface 5 s and the CTU removed from the tree 1 p. A productionchoke (not shown) may be connected to the flow cross 9 and to aseparation, treatment, and storage facility (not shown). Production ofthe fractured zones 7 may then commence.

Alternatively, the CT BHA may include a drilling motor, such as a mudmotor, and one or more mill bits. The milling BHA may then be operatedby pumping milling fluid through the coiled tubing to mill the plugdebris and the milling fluid may return the milled debris to thesurface.

FIG. 6A illustrates an alternative consumable frac plug 68, according toanother embodiment of the present invention. FIG. 6B illustrates anigniter 71 of the alternative frac plug 68. The frac plug 68 may includea consumable mandrel 77, the slips and the slip cones, the packing, andan igniter 71. The igniter 71 may include an upper portion of themandrel body 77 y, a ball seat 75, a inner housing 72, the pyrogencharge 45, the PCC 46 c, and a trigger. The trigger may include an outerhousing 70, one or more strikers, and a solute strip 73. Each strikermay include the pressure relief device 48, a plunger 50, the solvent 51,and a pressure port 74. The alternative frac plug 68 may operate in asimilar fashion to the frac plug 18. The pressure port 74 may be alongitudinal passage formed through the housing 70.

Alternatively, the pressure port may be a radial passage having thepressure relief device and plunger disposed therein and the longitudinalpassage may be used for containing the solvent vial.

FIG. 7A illustrates an electronic trigger 80 for use with either igniter31, 71, according to another embodiment of the present invention. Theelectronic trigger 80 may include a timer battery 81, a pressure switch82, an electronic timer switch 83, an ignition battery 84, and anignition valve 85. The trigger 80 may function in a similar fashion tothe trigger 47. The pressure switch 82 may close in response to fracturepressure. Closing of the pressure switch 82 may supply electricity tothe electronic timer switch 83 from the timer battery 81. The electronictimer switch 83 may commence countdown in response to being powered andclose at the end of countdown, thereby supplying electricity to theignition valve 85 from the ignition battery 84. The ignition valve 85may be an actuated shutoff valve disposed in each ignition port of theouter housing 40 instead of the respective solute plug 53 or in place ofthe solute disk 73. The ignition valve 85 may fail to the closedposition and open in response to being powered by the ignition battery84.

Alternatively, capacitors or inductors may be used instead of one orboth of the batteries 81, 84. Alternatively, the trigger may include anelectric match instead of the valve and the pyrogen may be a pyrotechniccomposition.

FIG. 7B illustrates an alternative switch 86 for the electronic trigger80, according to another embodiment of the present invention. Thealternative switch 86 may replace the pressure switch 86 and close inresponse to seating of the ball 17 in the ball seat 27 b, 75.

Alternatively, the switch may close in response to disconnection of thesetting tool from the frac plug.

FIG. 8 illustrates an alternative manufacturing system for analternative consumable mandrel (not shown), according to anotherembodiment of the present invention. The manufacturing system mayinclude the metering hopper 55 h, an extrusion die 91, a press 92, aheater 93, and a spool 94. The metering hopper 55 h may dispense thepyrotechnic composition 46 m into the die 91. A dispensing port of thedie may then be closed and a protective atmosphere 95 established aroundthe die 91 and the spool 94. The heater 93 may be operated to heat thedie 91 and pyrotechnic composition 46 m. The press 92 may then beoperated to extrude the heated pyrotechnic composition 46 m through anextrusion port of the die 91, thereby sintering the pyrotechniccomposition particulates into a fiber. The spool 94 may then be rotatedto wind the sintered fiber. The sintered pyrotechnic composition fibermay then be used instead of one of the fibers 57 f of the filamentwinding system of FIG. 4B with a non-infused resin.

Alternatively, the pyrotechnic composition may be cold pressed into abillet and the billet loaded into the die 91 and then hot extruded intoa sintered fiber. Alternatively, the sintered fiber may be used inconjunction with the infused resin 56 to manufacture the plug mandrel.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

The invention claimed is:
 1. A method of fracturing a production zone ina wellbore, comprising: deploying a packer or plug into the wellbore,the packer or plug comprising a composite material made from apyrotechnic composition; perforating a casing of the wellbore adjacentthe production zone; fracturing the production zone; and chemicallyreacting a charge of the packer or plug with a wellbore fluid so thatthe chemical reaction between the charge and the wellbore fluid ignitesto ignite the packer or plug.
 2. The method of claim 1, furthercomprising exposing the charge of the packer or plug to the wellborefluid after fracturing the production zone.
 3. The method of claim 1,further comprising exposing the charge of the packer or plug to thewellbore fluid after a predetermined time period.
 4. The method of claim1, further comprising operating an igniter to expose the charge of thepacker or plug to the wellbore fluid.
 5. The method of claim 1, furthercomprising closing a bore of the packer or plug before fracturing theproduction zone.
 6. The method of claim 1, further comprising deployinga second packer or plug into the wellbore; perforating the casing of thewellbore adjacent a second production zone; and fracturing the secondproduction zone.
 7. The method of claim 6, wherein the second packer orplug comprises a composite material made from a pyrotechnic composition.8. The method of claim 6, further comprising exposing a charge of thesecond packer or plug to the wellbore fluid to ignite the second packeror plug.
 9. The method of claim 1, wherein the charge reacts with waterin the wellbore fluid.
 10. The method of claim 1, further comprisinginitiating combustion of a mandrel of the packer or plug.
 11. A methodof fracturing a production zone in a wellbore, comprising: deploying apacker or plug into the wellbore, the packer or plug comprising acomposite material made from a pyrotechnic composition; perforating acasing of the wellbore adjacent the production zone; fracturing theproduction zone; exposing a charge of the packer or plug to a wellborefluid to ignite the packer or plug; and operating an igniter to exposethe charge of the packer or plug to the wellbore fluid, whereinoperating the igniter comprises: opening a pressure port of the igniter;releasing a solvent into an annular chamber of the packer or plug; anddissolving at least one solute plug to expose the annular chamber to thewellbore fluid.
 12. A method of fracturing a production zone in awellbore, comprising: deploying a packer or plug into the wellbore, thepacker or plug comprising a composite material made from a pyrotechniccomposition; perforating a casing of the wellbore adjacent theproduction zone; fracturing the production zone; exposing a charge ofthe packer or plug to a wellbore fluid to ignite the packer or plug; andoperating an igniter to expose the charge of the packer or plug to thewellbore fluid, wherein operating the igniter comprises: increasing apressure in the wellbore to a predetermined pressure; operating a switchin response to the predetermined pressure; and opening a valve to exposean annular chamber of the packer or plug to the wellbore fluid.
 13. Themethod of claim 12, wherein the predetermined pressure corresponds to afracturing pressure for the production zone.